Power generation process with partial recycle of carbon dioxide

ABSTRACT

Disclosed herein is a power generation process in which a portion of the carbon dioxide generated by gaseous fuel combustion is recycled back to the power generation process, either pre-combustion, post-combustion, or both. The power generation process of the invention may be a combined cycle process or a traditional power generation process. The process utilizes sweep-based membrane separation.

RELATED APPLICATIONS

This application claims the benefit of PCT Application No.PCT/US10/02480, filed Sep. 13, 2010, and U.S. application Ser. No.13/122,136, filed Mar. 31, 2011, the disclosures of which are herebyincorporated herein by reference in their entireties.

FIELD OF THE INVENTION

The invention pertains to a power generation process in which a portionof the carbon dioxide generated by gaseous fuel combustion is recycledback to the power generation process, either pre-combustion,post-combustion, or both. The power generation process may be a combinedcycle process or a traditional power generation process.

BACKGROUND OF THE INVENTION

In a traditional power generation process, a gaseous fuel (such asnatural gas or syngas) is combusted in the presence of oxygen, producinga stream of hot, high-pressure gas. This hot, high-pressure gas is thenused to drive a gas turbine, which in turn drives a generator, producingelectrical energy. The exhaust gas from the turbine is still very hotand may contain as much as 50% of the energy generated by the combustionprocess. This remaining heat (i. e. , in the form of hot exhaust fumes)is wasted.

In recent years, there has been considerable interest in combined cyclepower generation to improve the energy efficiency of the process. Acombined cycle power plant generates additional electricity by using thehot exhaust gas from a gas turbine to boil water to make steam. Thesteam, in turn, is used to drive a steam turbine, generating additionalelectricity. Combined cycle power generation processes are well-known inthe art and are described, for example, by Rolf Kehlhofer et al. inCombined-Cycle Gas & Steam Power Plants (3^(rd) ed., PennWellCorporation; Tulsa, Okla., 2009).

A flow diagram of a conventional gas turbine power generation process isshown in FIG. 6. In this unit, an incoming air stream 602 is compressedfrom atmospheric pressure to 20-30 bar in an air compressor unit 619.This compressed gas stream 603 is then combusted with the incoming fuelgas 601 (which is typically but not necessarily natural gas) incombustor 604. The hot, high-pressure gas from the combustor is thenexpanded through the gas turbine 606. The gas turbine 606 ismechanically linked to the air compressor 619 and an electrical powergenerator 611. The low-pressure exhaust gas exhaust gas 605 from the gasturbine 606 is still hot, so the energy content from this gas canoptionally be recovered in a steam boiler 612 which, in a combined cycleoperation, is used to make additional electricity in a secondary steam.turbine.

A major issue in the design of these units is the temperature of the gasleaving the combustor. This gas stream can be too hot to allow efficientand safe use in the gas turbine. For this reason, a diluent stream ofnitrogen or steam or other gas may be mixed with the air stream going tothe air compressor 619. This diluent stream serves to control thetemperature of stream 607 leaving the combustor. Oftentimes, the volumeof this diluent stream can be equal or more than the stoichiometricvolume of air required to combust the fuel.

Although nitrogen, steam, and other gases are used as a diluent, morecommonly, the gas entering the combustor 604 is diluted by using an airstream that is two or even three-fold larger than the stoichiometricvolume of gas required to combust the fuel. The excess air is theoxygen-containing gas that cools stream 607. In some cases, all of theair stream leaving the gas compressor 619 is sent to the combustor 604.But in other gas turbines, a portion of the compressed air may be mixedwith the combustion exhaust after the combustor, shown as optional gasstream 610. This mixing option may be done before the gas turbine orwithin the gas turbine.

When excess air is used as the oxygen-containing gas, the exhaust gas615 from the turbine will often only contain 4-5% carbon dioxide.Recovery of carbon dioxide from this dilute, low-pressure, yet veryhigh-volume gas stream is expensive. In recent years, a number ofturbine producers have modified the operation of these turbines by usinga portion 608 of the exhaust gas 615 as the oxygen-containing gas 613for air stream 602. Recycling the exhaust gas in this way increases thecarbon dioxide concentration in the final exhaust gas from 4-5% to 8-10%and reduces the volume of gas that must be treated if carbon dioxidesequestration is to be done. This process significantly reduces the costof carbon dioxide sequestration from the exhaust gas.

The amount of exhaust gas that can be recycled is limited by the oxygencontent of the gas mixture 603 delivered to the combustion chamber 604.When excess air is used as the diluent, this gas contains about 21%oxygen; when the exhaust gas is recycled and used as a diluent, theoxygen content can drop to 15% or less. If the oxygen content dropsbelow about 15%, changes to the turbine design will be required.

A combined cycle power generation process, in which the energy contentof the hot exhaust gas from the gas turbine is recovered in a steamboiler which is used to make additional electricity in a secondary steamturbine, is inherently more expensive than the more traditional, gasturbine-only power generation process due to the additional capitalequipment required. However, it is expected that the additional energygenerated will eventually more than off-set the cost of the additionalequipment. As a result, most new gas power plants in North America andEurope are combined cycle.

In either a traditional or combined cycle power generation process,combustion of gaseous fuels produces exhaust gases contaminated withcarbon dioxide that contribute to global warming and environmentaldamage. Such gas streams are difficult to treat in ways that are bothtechnically and economically practical, and there remains a need forbetter treatment techniques.

Combustion of gaseous fuels also generates enormous amounts of heat.Therefore, another consideration in the power generation process is tomoderate the temperature of the gas entering the turbine(s), to avoidmelting or otherwise damaging turbine components.

Gas separation by means of membranes is a well-established technology.In an industrial setting, a total pressure difference is usually appliedbetween the feed and permeate sides, typically by compressing the feedstream or maintaining the permeate side of the membrane under partialvacuum.

Although permeation by creating a feed to permeate pressure differenceis the most common process, it is known in the literature that a drivingforce for transmembrane permeation may be supplied by passing a sweepgas across the permeate side of the membranes, thereby lowering thepartial pressure of a desired permeant on that side to a level below itspartial pressure on the feed side. In this case, the total pressure onboth sides of the membrane may be the same, the total pressure on thepermeate side may be higher than on the feed side, or there may beadditional driving force provided by keeping the total feed pressurehigher than the total permeate pressure.

Using a sweep gas has most commonly been proposed in connection with airseparation to make nitrogen or oxygen-enriched air, or with dehydration.Examples of patents that teach the use of a sweep gas on the permeateside to facilitate air separation include U.S. Pat. Nos. 5,240,471;5,500,036; and 6,478,852. Examples of patents that teach the use of asweep gas in a dehydration process include U.S. Pat. Nos. 4,931,070;4,981,498; and 5,641,337.

Configuring the flow path within the membrane module so that the feedgas and sweep stream flow, as far as possible, countercurrent to eachother is also known, and taught, for example in U.S. Pat. Nos. 5,681,433and 5,843,209.

The use of a process including a membrane separation step operated insweep mode for treating flue gas to remove carbon dioxide is taught inco-owned and copending U.S. patent application Ser. No. 12/734,941,filed Jun. 2, 2010. The use of a process including a membrane separationstep operated in sweep mode for treating natural gas combustion exhaustto remove carbon dioxide is taught in co-owned and copending U.S. patentapplication Ser. No. 13/122,136, filed Mar. 31, 2011.

SUMMARY OF THE INVENTION

Embodiments of the invention pertain to power generating processes.Membrane-based gas separation is used to control carbon dioxideemissions from combustion of methane-containing gases, such as naturalgas, and methane gas combustion processes in which carbon dioxideemissions are produced. The invention includes processes for treatingexhaust gases from combustion of burnable gas mixtures other thannatural gas, such as syngas, refinery fuel gas, or blast furnaceoff-gas. Embodiments of the invention are applicable to both traditionaland combined cycle turbine power generation processes.

Power plants generate enormous amounts of flue gas. For example, amodestly sized 100 megawatt power plant may produce over 300 MMscfd ofexhaust (flue) gas.

The major components of combustion exhaust gases are normally nitrogen,carbon dioxide, and water vapor. Other components that may be present,typically only in small amounts, include oxygen, hydrogen, SO_(x),NO_(x), and unburnt hydrocarbons. Syngas may also contain heavy metals,such as mercury. The carbon dioxide concentration in the flue gas can beup to about 20 volume %, but in most power plants, the exhaust gascontains between 4-8% carbon dioxide. Separating the carbon dioxide fromthis very large dilute stream is complex. The processes described hereinproduce more concentrated and smaller exhaust streams. Downstreamseparation of concentrated carbon dioxide for sequestration or otheruses is then much more economical.

In addition to gaseous components, combustion flue gas—depending on thefuel used—may contain suspended particulate matter in the form of flyash and soot. This material is usually removed by several stages offiltration before the gas is sent to the stack. It is assumed hereinthat the flue gas has already been treated in this way, if desired,prior to carrying out the processes of the invention.

Embodiments of the invention involve treating the exhaust or flue gas toremove carbon dioxide into a small concentrate stream, while producing asecond carbon dioxide-depleted exhaust stream. In preferred embodiments,the carbon dioxide level of the carbon dioxide-depleted exhaust gas isreduced to as low as 5 volume % or less, and most preferably, to 3volume % or less, or even 2 volume % or less. Discharge of such a streamto the environment is much less damaging than discharge of the untreatedexhaust.

The fuel gas may be combusted by mixing with air, oxygen-enriched air,or pure oxygen. Combustion of methane-containing gas often requires thegas being burnt to be mixed with a diluent gas—either before or afterthe combustor—to control the temperature of the gas going to theturbine. Typically, the diluent is excess air, steam, or nitrogen, or,as in embodiments of the present invention, it may be provided bypartial recycling of the flue gas exhaust. In natural gas combustion,the volume of diluent may be equal or greater than the volume of airrequired for stoichiometric combustion of the gas.

The combustion step creates a combustor exhaust stream, which shouldpreferably comprise at least 2 volume % oxygen. A portion of thecombustor exhaust stream is then routed as at least a portion of aworking gas stream to a gas turbine, to generate electrical power andcreate a turbine exhaust stream.

A first portion of the turbine exhaust stream is routed as a recycle gasstream back to the power generation process, either pre- or (preferably)post-combustion. When the recycle gas stream is routed back to the powergeneration process after the combustion step, it joins the combustorexhaust stream from the combustion step as part of the working gasstream to the gas turbine. The working gas stream to the gas turbineshould preferably contain between about 1.5 to about 5 times excessoxygen-containing gas—most typically, between about 2 to about 3.5 timesexcess oxygen-containing gas—to decrease the temperature of the gasentering the turbine, to avoid melting or otherwise damaging turbinecomponents. As used herein, the term “oxygen-containing gas” refers toany combination of a combined permeate/sweep stream (discussed below), arecycled exhaust gas stream, and/or an additional air, oxygen, oroxygen-enriched air supply stream, and the term “excess” refers to theexcess volume over the stoichiometric volume of air needed for 100%combustion of fuel.

The purpose of the oxygen-containing gas is three-fold:

-   -   To combust the gaseous fuel;    -   To control the operating temperature of the combustor; and    -   To control the turbine temperature.        As such, the oxygen-containing gas must be present in a quantity        large enough to meet all three purposes.

When the recycle gas stream is routed back to the power generationprocess prior to the combustion step, it joins the stream ofoxygen-containing gas provided to the combustion step. Theoxygen-containing gas provided to the combustion step should preferablycomprise at least 15 volume % oxygen, to achieve complete combustion ofthe gaseous fuel.

Alternatively, one portion of the recycle gas stream may be routed backto the power generation process after the combustion step, and anotherportion of the recycle gas stream may be routed back after thecombustion step.

A second portion of the turbine exhaust stream is withdrawn as apartially concentrated carbon dioxide product stream, which can thenoptionally be sent for further processing or sequestration, such as byabsorption (such as amine scrubbing or chilled ammonia sorption),membrane separation, or condensation, by way of example and not by wayof limitation.

A third portion of the turbine exhaust stream is routed to a sweep-basedmembrane separation step in a membrane module containing membranes thatare selectively permeable to carbon dioxide over nitrogen and to carbondioxide over oxygen. In this way, carbon dioxide that is in this streamis selectively removed as a permeate stream, which is recirculated backto the power generation process. The carbon dioxide-depleted exhaust(residue) stream is vented.

It is preferred that the membranes provide a carbon dioxide permeance ofat least about 300 gpu, more preferably at least about 500 gpu, and mostpreferably at least about 1,000 gpu under the operating conditions ofthe process. High carbon dioxide permeances are needed to reduce thearea of membrane needed to remove carbon dioxide from the exhaust gas.The membrane should also have a high carbon dioxide/oxygen selectivityto minimize oxygen permeation from the sweep gas stream into the exhaustgas stream. A carbon dioxide/oxygen selectivity of at least about 5, ormore preferably 10, under the operating conditions of the process isdesirable.

By using the oxygen-containing gas stream destined for the combustor assweep gas, the membrane separation step is carried out in a veryefficient manner, and without introducing any additional unwantedcomponents into the combustion zone.

The process is particularly useful in applications that areenergy-sensitive, as is almost always the case when very large streamsfrom power plants are to be processed. The process is also particularlyuseful in separations that are pressure-ratio limited, as will beexplained in more detail below.

The sweep-based membrane separation step may be carried out using one ormore individual membrane modules. Any modules capable of operating underpermeate sweep conditions may be used. Preferably, the modules take theform of hollow-fiber modules, plate-and-frame modules, or spiral-woundmodules. All three module types are known, and their configuration andoperation in sweep, including counterflow sweep modes, is described inthe literature.

The process may use one membrane module, but in most cases, theseparation will use multiple membrane modules arranged in series orparallel flow arrangements, as is well known in the art. Any number ofmembrane modules may be used.

The process may optionally be augmented by operating the membrane unitwith higher total pressure on the feed side than on the permeate side,thereby increasing the transmembrane driving force for carbon dioxidepermeation. The second portion of the exhaust stream may be sent to themembrane unit without compression, or may be compressed. Slightcompression to a pressure from between about 1.5 bar up to about 5 bar,such as 2 bar, is preferred. The sweep stream preferably follows a sweepflow direction across the permeate side, the off-gas stream follows afeed flow direction across the feed side, and the sweep flow directionis substantially countercurrent to the feed flow direction. In thealternative, the relative flow directions may be substantiallycrosscurrent, or less preferred, cocurrent.

The residue stream from the sweep-based membrane separation step isreduced in carbon dioxide content to less than about 5 volume %, morepreferably to less than 3 volume %, and most preferably to less than 2volume %. This stream is typically, although not necessarily, dischargedto the environment. The substantial reduction of the carbon dioxidecontent in the raw exhaust greatly reduces the environmental impact ofdischarging the stream.

An objective of the invention is to substantially increase theconcentration of carbon dioxide in the carbon dioxide-rich exhauststream from the power generation process, so that the portion of theexhaust stream that is withdrawn, and optionally sent for furtherprocessing or sequestration, can itself be concentrated and capturedmore efficiently than would otherwise be possible.

If the gas needs to be transported to reach the equipment that carriesout the further processing, such as an amine or cryogenic plant,transportation of the partially concentrated carbon dioxide gas is farsimpler and less costly than transporting low concentration raw flue gasfrom a conventional power plant. Typically, the amount of gas that mustbe pipelined or otherwise transported to the processing plant is reducedseveral fold, such as to 50%, 30%, or even 25% or less of the amountthat would need to be sent if the membrane separation step were absent.This is a significant benefit of the invention.

The portion of the turbine exhaust stream that is recycled to the powergeneration process (i.e., the “first portion”) preferably comprisesbetween about 10 volume % and about 50 volume %, more preferably,between about 20 volume % and about 40 volume %, of the total turbineexhaust stream. The portion of the turbine exhaust stream that iswithdrawn for optional further processing (i.e., the “second portion”)preferably comprises between about 5 volume % and about 20 volume %,more preferably, between about 10 volume % and about 20 volume %, of thetotal turbine exhaust stream. The portion of the turbine exhaust streamthat is to be sent to the sweep-based membrane separation step (i.e.,the “third portion”) preferably comprises between about 40 volume % andabout 80 volume %, more preferably, between about 50 volume % and about70 volume %, of the total turbine exhaust stream. These volumepercentages can also be expressed as a split ratio, where the ratiodefines the relative proportions of the turbine exhaust stream sent toeach step. In general, we prefer to operate with a split ratio in therange of 3:1:6 (first portion:second portion:third portion).

Another objective of the invention is to minimize the amount of carbondioxide in the residue stream from the sweep-based membrane separationstep, which is often released to the environment. As such, the residuestream preferably comprises less than 5 volume % carbon dioxide; morepreferably, less than 3 volume % carbon dioxide; and, most preferably,less than 2 volume % carbon dioxide. Most preferably, at least 80% ofthe carbon dioxide generated in the power generation process isrecovered by the process of the invention. The substantial reduction ofthe carbon dioxide content in the raw exhaust greatly reduces theenvironmental impact of discharging the stream.

Accordingly, a basic embodiment of the invention as it relates to atraditional power generation process includes the following steps:

(a) performing a power generation process, comprising

-   -   (i) performing a combustion step by combusting a mixture        comprising a gaseous fuel and an oxygen-containing gas, thereby        generating a combustor exhaust stream comprising carbon dioxide        and nitrogen, and    -   (ii) routing the combustor exhaust stream as at least a portion        of a working gas stream to a gas turbine, thereby generating        electrical power and creating a turbine exhaust stream;

(b) routing a first portion of the turbine exhaust stream back to thepower generation process as a recycle gas stream;

(c) withdrawing a second portion of the turbine exhaust stream as apartially concentrated carbon dioxide product stream;

(d) routing a third portion of the turbine exhaust stream to asweep-based membrane separation step, wherein the sweep-based membraneseparation step comprises

-   -   (i) providing a membrane having a feed side and a permeate side,        and being selectively permeable to carbon dioxide over nitrogen        and to carbon dioxide over oxygen,    -   (ii) passing a feed gas comprising the third portion of the        turbine exhaust stream across the feed side,    -   (iii) passing air, oxygen-enriched air, or oxygen as a sweep        stream across the permeate side,    -   (iv) withdrawing from the feed side a carbon dioxide-depleted        stream,    -   (v) withdrawing from the permeate side a permeate stream        comprising oxygen and carbon dioxide; and

(e) passing the permeate stream back to the power generation process.

Another embodiment of the invention relates to a combined cycle powergeneration process. This embodiment includes the following steps:

(a) performing a combined cycle power generation process, comprising

-   -   (i) performing a combustion step by combusting a mixture        comprising a gaseous fuel and an oxygen-containing gas, thereby        generating a combustor exhaust stream comprising carbon dioxide        and nitrogen,    -   (ii) routing the combustor exhaust stream as at least a portion        of a working gas stream to a gas turbine, thereby generating        electrical power and creating a turbine exhaust stream,    -   (iii) routing at least a portion of the turbine exhaust stream        to a boiler, thereby generating steam and creating a boiler        exhaust stream, and    -   (iv) routing the steam to a steam turbine, thereby generating        additional electrical power;

(b) routing a first portion of the boiler exhaust stream back to thepower generation process as a recycle gas stream;

(c) withdrawing a second portion of the boiler exhaust stream as apartially concentrated carbon dioxide product stream;

(d) routing a third portion of the boiler exhaust stream to asweep-based membrane separation step, wherein the sweep-based membraneseparation step comprises

-   -   (i) providing a membrane having a feed side and a permeate side,        and being selectively permeable to carbon dioxide over nitrogen        and to carbon dioxide over oxygen,    -   (ii) passing a feed gas comprising the third portion of the        boiler exhaust stream across the feed side,    -   (iii) passing air, oxygen-enriched air, or oxygen as a sweep        stream across the permeate side,    -   (iv) withdrawing from the feed side a carbon dioxide-depleted        stream,    -   (v) withdrawing from the permeate side a permeate stream        comprising oxygen and carbon dioxide; and

(e) passing the permeate stream back to the power generation process.

In an alternative embodiment of the invention, the second portion of theturbine exhaust stream or (in the case of a combined cycle process, theboiler exhaust stream) is sent to a carbon dioxide capture step in amembrane module containing membranes that are selectively permeable tocarbon dioxide over nitrogen and to carbon dioxide over oxygen, andhaving the properties described above with respect to the membranes usedin the sweep-based membrane separation. The second portion of theturbine or boiler exhaust stream is flowed across the feed side of themembranes. A partially concentrated carbon dioxide product stream isthen withdrawn from the permeate side of the membrane. This partiallyconcentrated carbon dioxide stream can then be sent for furtherprocessing or sequestration, as described above.

A carbon dioxide-depleted stream is withdrawn from the feed side of themembrane unit. This carbon dioxide-depleted stream is then routed to thefeed side of a membrane separation module that is adapted for operationin sweep mode. As discussed above, the feed gas flows across the feedside of the membranes, and a sweep gas of air, oxygen-enriched air, oroxygen flows across the permeate side, to provide or augment the drivingforce for transmembrane permeation. The sweep stream picks up thepreferentially permeating carbon dioxide. The combined sweep/permeatestream is then withdrawn from the membrane unit and is returned to thepower generation process.

The portion of the turbine exhaust stream or (in the case of a combinedcycle process) boiler exhaust stream that is recycled to the powergeneration process (i.e., the “first portion”) preferably comprisesbetween about 10 volume % and about 50 volume %, more preferably,between about 20 volume % and about 40 volume %, of the total turbineexhaust stream. The portion of the turbine exhaust stream that is sentto the membrane-based carbon dioxide capture step (i.e., the “secondportion”) preferably comprises between about 50 volume % and about 90volume %, more preferably, between about 60 volume % and about 80 volume%, of the total turbine exhaust stream. As discussed above, these volumepercentages can also be expressed as a split ratio, where the ratiodefines the relative proportions of the turbine exhaust stream sent toeach step. In general, we prefer to operate with a split ratio in therange of 1:2 to about 1:3 (first portion:second portion).

Accordingly, a preferred embodiment of a process of the type describedabove includes the following steps:

(a) performing a power generation process, comprising

-   -   (i) performing a combustion step by combusting a mixture        comprising a gaseous fuel and an oxygen-containing gas, thereby        generating a combustor exhaust stream comprising carbon dioxide        and nitrogen, and    -   (ii) routing the combustor exhaust stream as at least a portion        of a working gas stream to a gas turbine, thereby generating        electrical power and creating a turbine exhaust stream;

(b) routing a first portion of the turbine exhaust stream back to thepower generation process as a recycle gas stream;

(c) routing a second portion of the turbine exhaust stream to amembrane-based carbon dioxide capture step, wherein the capture stepcomprises

-   -   (i) providing a first membrane having a first feed side and a        first permeate side, and being selectively permeable to carbon        dioxide over nitrogen and to carbon dioxide over oxygen,    -   (ii) passing the second portion of the turbine exhaust stream        across the first feed side,    -   (iii) withdrawing from the first permeate side a partially        concentrated carbon dioxide product stream,    -   (iv) withdrawing from the first feed side a carbon        dioxide-depleted stream

(d) routing the carbon dioxide-depleted stream to a sweep-based membraneseparation step, wherein the sweep-based membrane separation stepcomprises

-   -   (i) providing a second membrane having a second feed side and a        second permeate side, and being selectively permeable to carbon        dioxide over nitrogen and to carbon dioxide over oxygen,    -   (ii) passing a feed gas comprising the carbon dioxide-depleted        stream across the second feed side,    -   (iii) passing air, oxygen-enriched air, or oxygen as a sweep        stream across the second permeate side,    -   (iv) withdrawing from the second feed side a stream that is        depleted in carbon dioxide compared to the feed gas,    -   (v) withdrawing from the second permeate side a permeate stream        comprising oxygen and carbon dioxide; and

(e) passing the permeate stream back to the power generation process.

A preferred embodiment of a process of the type described above as itpertains to a combined cycle power generation process includes thefollowing steps:

(a) performing a combined cycle power generation process, comprising

-   -   (i) performing a combustion step by combusting a mixture        comprising a gaseous fuel and an oxygen-containing gas, thereby        generating a combustor exhaust stream comprising carbon dioxide        and nitrogen,    -   (ii) routing the combustor exhaust stream as at least a portion        of a working gas stream to a gas turbine, thereby generating        electrical power and creating a turbine exhaust stream,    -   (iii) routing at least a portion of the turbine exhaust stream        to a boiler, thereby generating steam and a creating a boiler        exhaust stream, and    -   (iv) routing the steam to a steam turbine, thereby generating        additional electrical power;

(b) routing a first portion of the boiler exhaust stream back to thepower generation process as a recycle gas stream;

(c) routing a second portion of the boiler exhaust stream to amembrane-based carbon dioxide capture step, wherein the capture stepcomprises

-   -   (i) providing a first membrane having a first feed side and a        first permeate side, and being selectively permeable to carbon        dioxide over nitrogen and to carbon dioxide over oxygen,    -   (ii) passing the second portion of the boiler exhaust stream        across the first feed side,    -   (iii) withdrawing from the first permeate side a partially        concentrated carbon dioxide product stream,    -   (iv) withdrawing from the first feed side a carbon        dioxide-depleted stream

(d) routing the carbon dioxide-depleted stream to a sweep-based membraneseparation step, wherein the sweep-based membrane separation stepcomprises

-   -   (i) providing a second membrane having a second feed side and a        second permeate side, and being selectively permeable to carbon        dioxide over nitrogen and to carbon dioxide over oxygen,    -   (ii) passing a feed gas comprising the carbon dioxide-depleted        stream across the second feed side,    -   (iii) passing air, oxygen-enriched air, or oxygen as a sweep        stream across the second permeate side,    -   (iv) withdrawing from the second feed side a stream that is        depleted in carbon dioxide compared to the feed gas,    -   (v) withdrawing from the second permeate side a permeate stream        comprising oxygen and carbon dioxide; and

(e) passing the permeate stream back to the power generation process.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a schematic drawing of a flow scheme for a basic embodimentof the process of the invention as it relates to a traditional powergeneration process. The process includes recycling a portion of thecarbon dioxide generated in the power generation process back to thepower generation process, as well as a sweep-based membrane separationstep.

FIG. 1B is a schematic drawing of a flow scheme for a basic embodimentof the process of the invention as it relates to a combined cycle powergeneration process.

FIG. 1C is a more detailed drawing of a flow scheme for an embodiment ofthe process of the invention.

FIG. 2A is a schematic drawing of a flow scheme for a preferredembodiment of the process of the invention as it relates to atraditional power generation process. This process further includes amembrane-based carbon dioxide capture step prior to the sweep-basedmembrane separation step.

FIG. 2B is a schematic drawing of a flow scheme for a preferredembodiment of the process of the invention as it relates to a combinedcycle power generation process.

FIG. 3 is a schematic drawing of a flow scheme for a power generationprocess that does not include carbon dioxide recycle or a sweep-basedmembrane separation step (not in accordance with the invention).

FIG. 4 is a schematic drawing of a flow scheme for a power generationprocess that does not include a sweep-based membrane separation step,but in which a portion of the exhaust stream generated in the powergeneration process is routed from the turbine back to the combustor (notin accordance with the invention).

FIG. 5 is a schematic drawing of a flow scheme for a power generationprocess that includes a sweep-based membrane separation step, but norecycle of combustion exhaust gas from the turbine to the combustor (notin accordance with the invention).

FIG. 6 is a flow diagram of a conventional gas turbine power generationprocess (not in accordance with the invention).

DETAILED DESCRIPTION OF THE INVENTION

Gas percentages given herein are by volume unless stated otherwise.

Pressures as given herein are in bar absolute unless stated otherwise.

The terms exhaust gas, off-gas, flue gas, and emissions stream are usedinterchangeably herein.

The terms natural gas, syngas, and fuel are used interchangeably herein.

The invention is a process for controlling carbon dioxide emissions fromcombustion of gaseous fuels, such as natural gas or the like, bymembrane-based gas separation, and gaseous fuel combustion processesincluding such gas separation. The process is expected to beparticularly useful for treating flue or exhaust gas from gas-firedpower plants, such as traditional or combined cycle plants, whichtypically use natural gas as fuel, and IGCC (Integrated GasificationCombined Cycle) plants, which use syngas, typically made by gasifyingcoal, as fuel.

In either a traditional plant or in a conventional combined cycle plant,it is common to dilute the mixture of gases in the combustion chamber byfeeding an excess of air, such as twice the flow needed to satisfy thestoichiometric ratio for the combustion reactions. The excess air doesnot take part in the reactions, but dilutes the combustion gases,thereby moderating the exhaust gas temperature. As an alternative or inaddition to feeding excess air, a portion of the exhaust gas itself issometimes returned to the combustor as part of the oxygen-containing gasto the combustor. In some IGCC plants, where the gasifier uses an oxygenfeed, nitrogen produced as a co-product of oxygen production is used asa diluent for the fuel gas being combusted.

In a traditional or combined cycle power plant, the gaseous fuel iscombusted to produce a hot gas that is used to drive a gas turbine,producing power. The exhaust gas from the combustor is still very hotand so can be used to boil water, producing steam that can then drive asteam turbine in a combined cycle plant.

A simple flow scheme for a basic embodiment of a power generationprocess in accordance with the invention, as it relates to a traditionalpower generation process, is shown in FIG. 1A. From FIG. 1A, it can beseen that a portion of the exhaust stream generated in the powergeneration process is routed back to the power generation process(either pre- or post-combustion), a portion of the exhaust stream iswithdrawn (for optional further processing), and a portion is sent to asweep-based membrane separation step.

Referring to FIG. 1A, fuel stream 101 and compressed oxygen-containinggas stream 109 are mixed and introduced as feed stream 103 intocombustion step or zone 104. Optionally, fuel stream 101 andoxygen-containing gas stream 109 can be introduced as separate streamsinto combustion step 104.

Oxygen-containing gas stream 109 may be made up of one or more of thefollowing three streams: diluent gas stream D1, diluent gas stream D2,and additional air, oxygen, or oxygen-enriched air stream 118. Diluentstream D1 originates from recycle stream 108; diluent stream D2originates from combined permeate/sweep stream 114. Streams 108 and 114will be discussed further in detail below.

Oxygen-containing gas stream 109 is typically compressed (compressor notshown in this figure) before being combined with fuel stream 101 (whichis at pressure) and introduced into the combustor 104. The ratios offuel 101 and oxygen-containing gas 109 may be adjusted as convenient inaccordance with known combustion principles.

The combustion step 104 generates combustion exhaust stream 105, whichpreferably contains at least 15 volume %; more preferably, at least 20volume %; and, most preferably, at least 25 volume %, carbon dioxide.This stream usually contains water vapor, nitrogen, and oxygen, inaddition to the carbon dioxide. Combustion exhaust stream 105 is thenrouted to gas turbine 106, which generates electrical power and turbineexhaust stream 107.

In one embodiment, combustion exhaust stream 105 is combined with eitherone or both of optional bypass streams B1 and B2, which are typicallycompressed (compressor not shown in this figure) before being combinedwith exhaust stream 105 to provide turbine working gas stream 116.Bypass stream B1 originates from recycle stream 108; bypass stream B2originates from combined permeate/sweep stream 114.

The invention embodiment described in the paragraph above is generallyless preferred with respect to existing power plants, because itrequires a second compressor train (not shown in this figure). Mostexisting plants only have one compressor train, situated upfront of thecombustor to compress the oxygen-containing stream to the combustor.However, future power plants may be built with two compressor trains, inwhich case, this process embodiment, in which either or both of therecycle stream 108 and the combined permeate/sweep stream 114 arerecycled to the power generation process post-combustion, may bepreferred.

Those skilled in the art will realize that changing the feed gascomposition to the turbine air compressor may affect the turbine'sefficiency and power output. In existing equipment, some changes to theturbine and combustor may be required to handle these changes. Newmachines would be built with modified compressor and combustor unitsdesigned to handle the differing gas compositions and achieve maximumefficiency.

Turbine exhaust stream 107 is then typically cooled to knock out water.Turbine exhaust stream 107 is then divided in a desired ratio into threeportions: a first portion 108 to be recycled back to the powergeneration process; a second portion 110 to be withdrawn for optionalfurther processing; and a third portion 111 to be sent to a sweep-basedmembrane separation step.

The first portion 108 of turbine exhaust stream 107 is routed back tothe power generation process, either prior to the combustion step 104 asdiluent stream D1, or after the combustion step, but prior to the gasturbine 106, as bypass stream B1, where it is combined with combustionexhaust stream 105 (and, optionally, with bypass stream B2) to formturbine working gas stream 116. Optionally, one portion of stream 108can be sent back to the power generation process pre-combustion asdiluent stream D1, and another portion can be sent to the powergeneration process post-combustion as bypass stream B1.

A second portion 110 of turbine exhaust stream 107 is withdrawn as apartially concentrated carbon dioxide product stream, which can thenoptionally be sent for further processing or sequestration, such as byabsorption (such as amine scrubbing or chilled ammonia sorption),membrane separation, or condensation, by way of example and not by wayof limitation.

A third portion 111 of turbine exhaust stream 107 is sent for treatmentin sweep-based membrane separation step or unit 112. The membraneseparation unit 112 contains membranes 113 that exhibit high permeancefor carbon dioxide, as well as high selectivity for carbon dioxide overnitrogen and oxygen.

Any membranes with suitable performance properties may be used. Manypolymeric materials, especially polar elastomeric materials, are verypermeable to carbon dioxide. Preferred membranes for separating carbondioxide from nitrogen or other inert gases have a selective layer basedon a polyether. A number of membranes are known to have high carbondioxide/nitrogen selectivity, such as 30, 40, 50, or above, and carbondioxide/oxygen selectivity of 10, 15, 20, or above (although theselectivity may be lower under actual operating conditions). Arepresentative preferred material for the selective layer is Pebax®, apolyamide-polyether block copolymer material described in detail in U.S.Pat. No. 4,963,165. We have found that membranes using Pebax® as theselective polymer can maintain a carbon dioxide/nitrogen selectivity of20 or greater under process conditions.

The membrane may take the form of a homogeneous film, an integralasymmetric membrane, a multilayer composite membrane, a membraneincorporating a gel or liquid layer or particulates, or any other formknown in the art. If elastomeric membranes are used, the preferred formis a composite membrane including a microporous support layer formechanical strength and a rubbery coating layer that is responsible forthe separation properties.

The membranes may be manufactured as flat sheets or as fibers and housedin any convenient module form, including spiral-wound modules,plate-and-frame modules, and potted hollow-fiber modules. The making ofall these types of membranes and modules is well known in the art. Toprovide countercurrent flow of the sweep gas stream, the modulespreferably take the form of hollow-fiber modules, plate-and-framemodules, or spiral-wound modules.

Flat-sheet membranes in spiral-wound modules is the most preferredchoice for the membrane/module configuration. A number of designs thatenable spiral-wound modules to be used in counterflow mode with orwithout sweep on the permeate side have been devised. A representativeexample is described in U.S. Pat. No. 5,034,126, to Dow Chemical.

Membrane step or unit 112 may contain a single membrane module or bankof membrane modules or an array of modules. A single unit or stagecontaining one or a bank of membrane modules is adequate for manyapplications. If the residue stream requires further purification, itmay be passed to a second bank of membrane modules for a secondprocessing step. If the permeate stream requires further concentration,it may be passed to a second bank of membrane modules for a second-stagetreatment. Such multi-stage or multi-step processes, and variantsthereof, will be familiar to those of skill in the art, who willappreciate that the membrane separation step may be configured in manypossible ways, including single-stage, multistage, multistep, or morecomplicated arrays of two or more units in serial or cascadearrangements.

Although the membrane modules are typically arranged horizontally, avertical configuration may in some cases be preferred to reduce the riskof deposition of particulates on the membrane feed surface.

The separation of components achieved by the membrane unit depends notonly on the selectivity of the membrane for the components to beseparated, but also on the pressure ratio. By pressure ratio, we meanthe ratio of total feed pressure/total permeate pressure. In pressuredriven processes, it can be shown mathematically that the enrichment ofa component (that is, the ratio of component permeate partialpressure/component feed partial pressure) can never be greater than thepressure ratio. This relationship is true, irrespective of how high theselectivity of the membrane may be.

Further, the mathematical relationship between pressure ratio andselectivity predicts that whichever property is numerically smaller willdominate the separation. Thus, if the numerical value of the pressureratio is much higher than the selectivity, then the separationachievable in the process will not be limited by the pressure ratio, butwill depend on the selectivity capability of the membranes. Conversely,if the membrane selectivity is numerically very much higher than thepressure ratio, the pressure ratio will limit the separation. In thiscase, the permeate concentration becomes essentially independent of themembrane selectivity and is determined by the pressure ratio alone.

High pressure ratios can be achieved by compressing the feed gas to ahigh pressure or by using vacuum pumps to create a lowered pressure onthe permeate side, or a combination of both. However, the higher theselectivity, the more costly in capital and energy it becomes to achievea pressure ratio numerically comparable with or greater than theselectivity.

From the above, it can be seen that pressure-driven processes usingmembranes of high selectivity for the components to be separated arelikely to be pressure ratio-limited. For example, a process in which amembrane selectivity of 40, 50, or above is possible (such as is thecase for many carbon dioxide/nitrogen separations) will only be able totake advantage of the high selectivity if the pressure ratio is ofcomparable or greater magnitude.

The inventors have overcome this problem and made it possible to utilizemore of the intrinsic selective capability of the membrane by dilutingthe permeate with the sweep gas, stream 102, thereby preventing thepermeate side concentration building up to a limiting level.

This mode of operation can be used with a pressure ratio of 1, that is,with no total pressure difference between the feed and permeate sides,with a pressure ratio less than 1, that is, with a higher total pressureon the permeate side than on the feed side, or with a relatively modestpressure ratio of less than 10 or less than 5, for example.

The driving force for transmembrane permeation is supplied by loweringthe partial pressure of the desired permeant on the permeate to a levelbelow its partial pressure on the feed side. The use of the sweep gasstream 102 maintains a low carbon dioxide partial pressure on thepermeate side, thereby providing driving force.

The partial pressure on the permeate side may be controlled by adjustingthe flow rate of the sweep stream to a desired value. In principle, theratio of sweep gas flow to feed gas flow may be any value that providesthe desired results, although the ratio sweep gas flow:feed gas flowwill seldom be less than 0.5 or greater than 2. High ratios (that is,high sweep flow rate) achieve maximum carbon dioxide removal from thefeed, but a comparatively carbon dioxide dilute permeate stream (thatis, comparatively low carbon dioxide enrichment in the sweep gas exitingthe modules). Low ratios (that is, low sweep flow rate) achieve highconcentrations of carbon dioxide in the permeate, but relatively lowlevels of carbon dioxide removal from the feed.

Use of a sweep rate that is too low may provide insufficient drivingforce for a good separation, and use of an overly high sweep flow ratemay lead to pressure drop or other problems on the permeate side, or mayadversely affect the stoichiometry in the reaction vessel. Typically andpreferably, the flow rate of the sweep stream should be between about50% and 300% of the flow rate of the membrane feed stream; morepreferably, between about 80% and 200%; and, most preferably, betweenabout 80% and 150%.

The total gas pressures on each side of the membrane may be the same ordifferent, and each may be above or below atmospheric pressure. Asmentioned above, if the pressures are about the same, the entire drivingforce is provided by the sweep mode operation.

In many cases, however, flue gas is available at atmospheric pressure,and _(t)he volumes of the streams involved are so large that it is notpreferred to use either significant compression on the feed side orvacuum on the permeate side. However, slight compression, such as fromatmospheric to a few bar, such as 1.5, 2, 3, 4, or 5 bar, for example,can be helpful and can provide part of a total carbon dioxide captureand recovery process that is relatively energy efficient, as shown inthe examples below. Further, if the combustion step is performed at highpressure, such as at 20 bar or 30 bar, as in a combined cycle plant, forexample, then process designs that involve compressing the exhaust gasto higher pressures can be contemplated. These designs enable theportion of gas sent to the carbon dioxide capture step to be sent atpressure, and enable the membrane separation step to be operated with arelatively high pressure on the permeate side, thereby reducing theamount of compression needed before the permeate/sweep stream enters thecombustor.

Returning to FIG. 1A, the third portion 111 of turbine exhaust stream107 flows across the feed side of the membranes 113; a sweep gas of air,oxygen-enriched air, or oxygen stream 102, flows across the permeateside. The sweep stream 102 picks up the preferentially permeating carbondioxide, and the resulting combined permeate/sweep stream 114 iswithdrawn from the membrane unit and is sent back to the powergeneration process as either one or both of diluent stream D2 and bypassstream B2.

Diluent stream D2 may be combined with optional diluent stream D1 and/oroptional additional air or oxygen supply stream 118, then compressed(compressor not shown in this figure) to form oxygen-containing gasstream 109, which is combined with fuel stream 101 to form feed stream103 to the combustor 104. In the alternative, if post-, rather thanpre-, combustion recycle is desired (which may require the presence of asecond compressor train), diluent streams D1 and D2 may be omitted, andthe entirety of the oxygen-containing gas stream 109 to the combustor104 may be provided by air stream 118.

An additional benefit of using the combustion oxygen-containing gassupply as the permeate sweep is that the permeating carbon dioxideremoved into the sweep gas is recycled to the combustion chamber. Thisincreases the carbon dioxide concentration in the exhaust gas leavingthe combustor, facilitating the downstream capture of carbon dioxide.

The residue stream 115 resulting from the sweep-based membraneseparation step 112 is reduced in carbon dioxide content to less thanabout 5 volume %; more preferably, to less than 3 volume %; and, mostpreferably, to less than 2 volume %. The residue stream 115 is typicallydischarged to the environment as treated flue gas.

The proportions of the flue gas that are directed to the recycle step108, the withdrawal step 110, and the sweep-based membrane separationstep 112 may be adjusted in conjunction with other operating parametersto tailor the processes of the invention to specific circumstances.

One of the goals of the process is to increase the carbon dioxideconcentration in the feed stream to the withdrawal step, because manycarbon dioxide separation technologies, such as amine scrubbing andcryogenic condensation, have capital and/or operating costs that scalewith the concentration of the component to be captured. The membraneseparation step preferentially permeates carbon dioxide and returns itto the combustor, thereby forming a loop between the combustor and themembrane unit in which the carbon dioxide concentration can build up.

The more exhaust gas that is directed to the membrane unit, the greateris the potential to increase the carbon dioxide concentration in theloop. However, the amount of membrane area needed will increase inproportion to the volume flow of gas directed to the membrane unit.Furthermore, most membrane materials have slight selectivity for oxygenover nitrogen, so a little oxygen from the air sweep stream will tend tocounter-permeate to the feed side of the membranes and be lost in theresidue stream. Consequently, the concentration of oxygen in thecombustor may drop, giving rise to the possibility of incompletecombustion or other problems. As an indication that the combustion stepis still being provided with an adequate supply of oxygen, we prefer theprocess to be operated so as to provide an oxygen concentration of atleast about 3 volume % in the exhaust gas stream 105 from the turbine(based on the composition after water removal).

The portion of the turbine exhaust stream that is recycled to the powergeneration process (i.e., the “first portion”) preferably comprisesbetween about 10 volume % and about 50 volume %, more preferably,between about 20 volume % and about 40 volume %, of the total turbineexhaust stream. The portion of the turbine exhaust stream that iswithdrawn for optional further processing (i.e., the “second portion”)preferably comprises between about 5 volume % and about 20 volume %,more preferably, between about 10 volume % and about 20 volume %, of thetotal turbine exhaust stream. The portion of the turbine exhaust streamthat is to be sent to the sweep-based membrane separation step (i.e.,the “third portion”) preferably comprises between about 40 volume % andabout 80 volume %, more preferably, between about 50 volume % and about70 volume %, of the total turbine exhaust stream. These volumepercentages can also be expressed as a split ratio, where the ratiodefines the relative proportions of the turbine exhaust stream sent toeach step. In general, we prefer to operate with a split ratio in therange of 3:1:6 (first portion:second portion:third portion).

A simple flow scheme for a basic embodiment of a power generationprocess in accordance with the invention, as it relates to a combinedcycle power generation process, is shown in FIG. 1B.

Referring to FIG. 1B, fuel stream 151 and compressed oxygen-containinggas stream 159 are mixed and introduced as feed stream 153 intocombustion step or zone 154. Optionally, fuel stream 151 andoxygen-containing gas stream 159 can be introduced as separate streamsinto combustion step 154.

Oxygen-containing gas stream 159 may be made up of one or more of thefollowing three streams: diluent gas stream D1, diluent gas stream D2,and additional air, oxygen, or oxygen-enriched air stream 168. Diluentstream D1 originates from recycle stream 158; diluent stream D2originates from combined permeate/sweep stream 164 (as described above,with respect to the invention embodiment described in the previousparagraphs).

Oxygen-containing gas stream 159 is typically compressed (compressor notshown in this figure) before being combined with fuel stream 151 (whichis at pressure) and introduced into the combustor 154. The ratios offuel 151 and oxygen-containing gas 159 may be adjusted as convenient inaccordance with known combustion principles, such as to meet thetemperature control needs of a combined cycle operation.

The combustion step 154 generates combustion exhaust stream 155, whichpreferably contains at least 15 volume %; more preferably, at least 20volume %; and, most preferably, at least 25 volume %, carbon dioxide.This stream usually contains water vapor, nitrogen, and oxygen, inaddition to the carbon dioxide. Combustion exhaust stream 155 is thenrouted to gas turbine 156, which generates electrical power and turbineexhaust stream 157.

In one embodiment, combustion exhaust stream 155 is combined with eitherone or both of optional bypass streams B1 and B2, which are typicallycompressed (compressor not shown in this figure) before being combinedwith exhaust stream 155 to provide turbine working gas stream 166.Bypass stream B1 originates from recycle stream 158; bypass stream B2originates from combined permeate/sweep stream 164.

In accordance with a combined cycle process, turbine exhaust stream 157is then routed to a boiler 169 to generate steam 170, which is routed toa steam turbine 171 to produce additional electrical power.

The exhaust stream 172 from boiler 169 is then typically cooled to knockout water. Boiler exhaust stream 172 is then divided in a desired ratiointo three portions: a first portion 158 to be recycled back to thepower generation process; a second portion 160 to be withdrawn foroptional further processing; and a third portion 161 to be sent to asweep-based membrane separation step.

The first portion 158 of boiler exhaust stream 172 is routed back to thepower generation process, either prior to the combustion step 154 asdiluent stream D1, or after the combustion step, but prior to the gasturbine 156, as bypass stream B1, where it is combined with combustionexhaust stream 155 (and, optionally, with bypass stream B2) to formturbine working gas stream 166. Optionally, one portion of stream 158can be sent back to the power generation process pre-combustion asdiluent stream D1, and another portion can be sent to the powergeneration process post-combustion as bypass stream B1.

A second portion 160 of boiler exhaust stream 172 is withdrawn as apartially concentrated carbon dioxide product stream, which can thenoptionally be sent for further processing or sequestration, such as byabsorption (such as amine scrubbing or chilled ammonia sorption),membrane separation, or condensation, by way of example and not by wayof limitation.

A third portion 161 of boiler exhaust stream 172 is sent for treatmentin sweep-based membrane separation step or unit 162. The membraneseparation unit 162 contains membranes 163 that exhibit the propertiesdescribed above with respect to the basic embodiment of the inventiondepicted in FIG. 1A.

The third portion 161 of boiler exhaust stream 172 flows across the feedside of the membranes 163; a sweep gas of air, oxygen-enriched air, oroxygen stream 152, flows across the permeate side. The sweep stream 152picks up the preferentially permeating carbon dioxide, and the resultingcombined permeate/sweep stream 164 is withdrawn from the membrane unitand is sent back to the power generation process as either one or bothof diluent stream D2 and bypass stream B2.

Diluent stream D2 may be combined with optional diluent stream D1 and/oroptional additional air or oxygen supply stream 168, then compressed(compressor not shown in this figure) to form oxygen-containing gasstream 159, which is combined with fuel stream 151 to form feed stream153 to the combustor 154. In the alternative, if post-, rather thanpre-, combustion recycle is desired (which may require the presence of asecond compressor train), diluent streams D1 and D2 may be omitted, andthe entirety of the oxygen-containing gas stream 159 to the combustor154 may be provided by air stream 168.

The residue stream 165 resulting from the sweep-based membraneseparation step 162 is reduced in carbon dioxide content to less thanabout 5 volume %; more preferably, to less than 3 volume %; and, mostpreferably, to less than 2 volume %. The residue stream 165 is typicallydischarged to the environment as treated flue gas.

The proportions of the flue gas that are directed to the recycle step158, the withdrawal step 160, and the sweep-based membrane separationstep 162 may be adjusted in conjunction with other operating parametersto tailor the processes of the invention to specific circumstances, asdiscussed above with respect to the invention embodiment depicted inFIG. 1A.

FIG. 1C is a more detailed drawing of a flow scheme for an embodiment ofthe process of the invention. Referring to FIG. 1C, an incomingoxygen-containing gas stream 144 is compressed from atmospheric pressurein an air compressor unit 139. Stream 144 is made up of diluent streamD1, diluent stream D2, and/or additional air or oxygen supply stream142. Diluent stream D1 originates from recycle stream 128; diluentstream D2 originates from combined sweep/permeate stream 134.

The resulting compressed gas stream 123 is then combusted with theincoming fuel gas 121 in combustor 124. The hot, high-pressure gas 133from the combustor 121 is then expanded through the gas turbine 126. Thegas turbine 126 is mechanically linked to the air compressor 139 and anelectrical power generator 141. The low-pressure exhaust gas exhaust gas127 from the gas turbine 126 is still hot, so the energy content fromthis gas can optionally be recovered in a steam boiler 143 which, in acombined cycle operation, is used to make additional electricity in asecondary steam turbine.

A first portion 128 of turbine exhaust stream 127 is routed back to thepower generation process, either through compressor 139 as diluentstream D1, or through a second, optional compressor 125 as bypass streamB1. Bypass stream B1 is compressed, then routed as gas stream 129 to gasturbine 126. Optionally, diluent stream D1 can be combined with diluentstream D2 and optional air stream 142 to form stream 144, which iscompressed as stream 123, a portion 140 of which can then be routed togas turbine 126. If it is to be routed back pre-combustion, diluentstream D1 is combined with diluent stream D2 and optional air stream 142to form stream 144, which is compressed as stream 123 and sent directlyto combustor 124.

A second portion 130 of turbine exhaust stream 127 is withdrawn as apartially concentrated carbon dioxide product stream, which can thenoptionally be sent for further processing or sequestration, such as byabsorption (such as amine scrubbing or chilled ammonia sorption),membrane separation, or condensation, by way of example and not by wayof limitation.

A third portion 131 of turbine exhaust stream 127 is sent for treatmentin sweep-based membrane separation step or unit 132. A sweep gas of air,oxygen-enriched air, or oxygen stream 122 picks up the preferentiallypermeating carbon dioxide, and the resulting combined permeate/sweepstream 134 is withdrawn from the membrane unit and is sent back to thepower generation process as either one or both of diluent stream D2 andbypass stream B2. Residue stream 135 is withdrawn and typically releasedto the environment.

As discussed above, in a traditional combustion process, air,oxygen-enriched air, or oxygen is often used as the sweep stream 122 tomembrane unit 132. However, in an IGCC operation, nitrogen may be usedas the sweep stream 122. In this case, combined permeate/sweep stream134 is routed back to second compressor 125 as bypass stream B2, whichis compressed and then routed as stream 129 to gas turbine 126. Theentire volume of air flow to the first compressor 139 is then providedby air stream 142, which is compressed and routed as stream 123 tocombustor 124.

Diluent stream D2 may be combined with diluent stream D1 and/or optionaladditional air or oxygen supply stream 142 to form oxygen-containing gasstream 144 to first compressor 139. Optionally, a portion ofpermeate/sweep stream 134 can be sent as bypass stream B2, which may becombined with bypass stream B1 and sent to optional second compressor125 and back to the power generation process post-combustion.

Mixing compressed recycle gas 129 with the exhaust gas 133 fromcombustor 124 is often a preferred way of operating the system. Stream129 will generally have a high carbon dioxide content, but a relativelylow oxygen content. If the gas is mixed with the feed air to thecombustor, the resulting mixture may have a relatively low oxygenconcentration, containing less than 20%, and possibly less than 15%oxygen, or even less. Complete combustion of the fuel gas 121 in thecombustor 124 may then not occur, or the flame produced in the combustormay not be stable.

An alternative embodiment of the invention, in which a membrane-basedcarbon dioxide capture step is performed in advance of the sweep-basedseparation step, is illustrated schematically in FIG. 2A. The flowscheme depicted in FIG. 2A is for a traditional power generationprocess.

Referring to FIG. 2A, fuel stream 201 and compressed oxygen-containinggas stream 219 are mixed and introduced as feed stream 203 intocombustion step or zone 204. Optionally, fuel stream 201 andoxygen-containing gas stream 219 can be introduced as separate streamsinto combustion step 204.

Oxygen-containing gas stream 219 may be made up of one or more of thefollowing three streams: diluent gas stream D1, diluent gas stream D2,and additional air, oxygen, or oxygen-containing air stream 218. Diluentstream D1 originates from recycle stream 208; diluent stream D2originates from combined permeate/sweep stream 216.

Oxygen-containing gas stream 219 is typically compressed (compressor notshown in this figure) before being combined with fuel stream 201 (whichis at pressure) and introduced into the combustor 204. The ratios offuel 201 and oxygen-containing gas 219 may be adjusted as convenient inaccordance with known combustion principles.

The combustion step 204 generates combustion exhaust stream 205, whichpreferably contains at least 15 volume %; more preferably, at least 20volume %; and, most preferably, at least 25 volume %, carbon dioxide.This stream usually contains water vapor, nitrogen, and oxygen, inaddition to the carbon dioxide. Combustion exhaust stream 205 is thenrouted to gas turbine 206, which generates electrical power and turbineexhaust stream 207.

In one embodiment, combustion exhaust stream 205 is combined with eitherone or both of optional bypass streams B1 and B2, which are typicallycompressed (compressor not shown in this figure) before being combinedwith exhaust stream 205 to provide turbine working gas stream 220.Bypass stream B1 originates from recycle stream 208; bypass stream B2originates from combined permeate/sweep stream 216.

Turbine exhaust stream 207 is then typically condensed to knock outwater. Turbine exhaust stream 207 is then divided in a desired ratiointo two portions: a first portion 208 to be recycled back to the powergeneration process, and a second portion 209 to be sent to amembrane-based carbon dioxide capture step 210.

The first portion 208 of turbine exhaust stream 207 is routed back tothe power generation process, either prior to the combustion step 204 asdiluent stream D1, or after the combustion step 204, but prior to thegas turbine 206, as bypass stream B1, where it is combined withcombustion exhaust stream 205 (and, optionally, with bypass stream B2)to form turbine working gas stream 220. Optionally, one portion ofstream 208 can be sent back to the power generation processpre-combustion as diluent stream D1, and another portion can be sent tothe power generation process post-combustion as bypass stream B1.

A second portion 209 of turbine exhaust stream 207 is sent to a carbondioxide capture step in a membrane module 210 containing membranes 211that are selectively permeable to carbon dioxide over nitrogen and tocarbon dioxide over oxygen, and having the properties described abovewith respect to the membranes used in the sweep-based membraneseparation step in the invention embodiment depicted schematically inFIG. 1A.

The second portion 209 of turbine exhaust stream 207 is flowed acrossthe feed side of the membranes 211. A partially concentrated carbondioxide product stream 212 is then withdrawn from the permeate side ofthe membrane 211.

A carbon dioxide-depleted stream 213 is withdrawn from the feed side ofthe membrane unit 210. This carbon dioxide-depleted stream 213 is thenrouted to the feed side of a membrane separation module 214 that isadapted to be operated in sweep mode. Membrane module 214 containsmembranes 215 that are selectively permeable to carbon dioxide overnitrogen and to carbon dioxide over oxygen, and having the propertiesdescribed above with respect to the membranes used in the sweep-basedmembrane separation step in the invention embodiment depictedschematically in FIG. 1A.

As discussed above, the feed gas 213 flows across the feed side of themembranes 215, and a sweep gas 202 of air, oxygen-enriched air, oroxygen flows across the permeate side, to provide or augment the drivingforce for transmembrane permeation. The sweep stream 202 picks up thepreferentially permeating carbon dioxide, and the resulting combinedpermeate/sweep stream 216 is withdrawn from the membrane unit and issent back to the power generation process as either one or both ofdiluent stream D2 and bypass stream B2.

Diluent stream D2 may be combined with optional diluent stream D1 and/oroptional additional air or oxygen supply stream 218, then compressed(compressor not shown in this figure) to form oxygen-containing gasstream 219, which is combined with fuel stream 201 to form feed stream203 to the combustor 204. In the alternative, if post-, rather thanpre-, combustion recycle is desired (which may require the presence of asecond compressor train), diluent streams D1 and D2 may be omitted, andthe entirety of the oxygen-containing gas stream 219 to the combustor204 may be provided by air stream 218.

The residue stream 217 resulting from the sweep-based membraneseparation step 214 is reduced in carbon dioxide content to less thanabout 5 volume %; more preferably, to less than 3 volume %; and, mostpreferably, to less than 2 volume %. The residue stream 214 is typicallydischarged to the environment as treated flue gas.

The proportions of the flue gas that are directed to the recycle step208 and the membrane steps 210/214 may be adjusted in conjunction withother operating parameters to tailor the processes of the invention tospecific circumstances. With respect to this embodiment of theinvention, we believe that it is preferable to operate the process witha split ratio of between 1:2 and 1:3 (recycle:membrane). A split ratioof 1:2 means that 33 volume % is directed to the recycle step and 67volume % to the membrane steps. In the 1:3 case, 25 volume % passes tothe recycle step and 75 volume % passes to the membrane steps.

A simple flow scheme for a preferred embodiment of a power generationprocess in accordance with the invention, as it relates to a combinedcycle power generation process, is shown in FIG. 2B.

Referring to FIG. 2B, fuel stream 251 and compressed oxygen-containinggas stream 269 are mixed and introduced as feed stream 253 intocombustion step or zone 254. Optionally, fuel stream 251 andoxygen-containing gas stream 269 can be introduced as separate streamsinto combustion step 254.

Oxygen-containing gas stream 269 may be made up of one or more of thefollowing three streams: diluent gas stream D1, diluent gas stream D2,and additional air, oxygen, or oxygen-containing air stream 268. Diluentstream D1 originates from recycle stream 258; diluent stream D2originates from combined permeate/sweep stream 266.

Oxygen-containing gas stream 269 is typically compressed (compressor notshown in this figure) before being combined with fuel stream 251 (whichis at pressure) and introduced into the combustor 254. The ratios offuel 251 and oxygen-containing gas 269 may be adjusted as convenient inaccordance with known combustion principles, such as to meet thetemperature control needs of a combined cycle operation, as mentionedabove.

The combustion step 254 generates combustion exhaust stream 255, whichpreferably contains at least 15 volume %; more preferably, at least 20volume %; and, most preferably, at least 25 volume %, carbon dioxide.This stream usually contains water vapor, nitrogen, and oxygen, inaddition to the carbon dioxide. Combustion exhaust stream 255 is thenrouted to gas turbine 256, which generates electrical power and turbineexhaust stream 257.

In one embodiment, combustion exhaust stream 255 is combined with eitherone or both of optional bypass streams B1 and B2, which are typicallycompressed (compressor not shown in this figure) before being combinedwith exhaust stream 255 to provide turbine working gas stream 270.Bypass stream originates from recycle stream 258; bypass stream B2originates from combined permeate/sweep stream 266.

In accordance with a combined cycle process, turbine exhaust stream 257is then routed to a boiler 272 to generate steam 273, which is routed toa steam turbine 274 to produce additional electrical power.

The exhaust stream 275 from boiler 272 is then typically cooled to knockout water. Boiler exhaust stream 275 is then divided in a desired ratiointo two portions: a first portion 258 to be recycled back to the powergeneration process, and a second portion 259 to be sent to amembrane-based carbon dioxide capture step 260.

The first portion 258 of boiler exhaust stream 275 is routed back to thepower generation process, either prior to the combustion step 254 asdiluent stream D1, or after the combustion step, but prior to the gasturbine 256, as bypass stream B1, where it is combined with combustionexhaust stream 255 (and, optionally, with bypass stream B2) to formturbine working gas stream 270. Optionally, one portion of stream 258can be sent back to the power generation process pre-combustion asdiluent stream D1, and another portion can be sent to the powergeneration process post-combustion as bypass stream B1.

A second portion 259 of boiler exhaust stream 275 is sent to a carbondioxide capture step in a membrane module 260 containing membranes 261that are selectively permeable to carbon dioxide over nitrogen and tocarbon dioxide over oxygen, and having the properties described abovewith respect to the membranes used in the sweep-based membraneseparation step in the invention embodiment depicted schematically inFIG. 1A.

The second portion 259 of boiler exhaust stream 275 is flowed across thefeed side of the membranes 261. A partially concentrated carbon dioxideproduct stream 262 is then withdrawn from the permeate side of themembrane 261

A carbon dioxide-depleted stream 263 is withdrawn from the feed side ofthe membrane unit 260. This carbon dioxide-depleted stream 263 is thenrouted to the feed side of a membrane separation module 264 that isadapted to operate in sweep mode. Membrane module 264 contains membranes265 that are selectively permeable to carbon dioxide over nitrogen andto carbon dioxide over oxygen, and having the properties described abovewith respect to the membranes used in the sweep-based membraneseparation step in the invention embodiment depicted schematically inFIG. 1A.

As discussed above, the feed gas 263 flows across the feed side of themembranes 265, and a sweep gas 252 of air, oxygen-enriched air, oroxygen flows across the permeate side, to provide or augment the drivingforce for transmembrane permeation. The sweep stream 252 picks up thepreferentially permeating carbon dioxide, and the resulting combinedpermeate/sweep stream 266 is withdrawn from the membrane unit and issent back to the power generation process as either one or both ofdiluent stream D2 and bypass stream B2.

Diluent stream D2 may be combined with optional diluent stream D1 and/oroptional additional air or oxygen supply stream 268, then compressed(compressor not shown in this figure) to form oxygen-containing gasstream 269, which is combined with fuel stream 251 to form feed stream253 to the combustor 254. In the alternative, if post-, rather thanpre-, combustion recycle is desired (which may require the presence of asecond compressor train), diluent streams D1 and D2 may be omitted, andthe entirety of the oxygen-containing gas stream 269 to the combustor254 may be provided by air stream 268.

The residue stream 267 resulting from the sweep-based membraneseparation step 264 is reduced in carbon dioxide content to less thanabout 5 volume %; more preferably, to less than 3 volume %; and, mostpreferably, to less than 2 volume %. The residue stream 264 is typicallydischarged to the environment as treated flue gas.

The proportions of the flue gas that are directed to the recycle step258 and the membrane steps 260/264 may be adjusted in conjunction withother operating parameters to tailor the processes of the invention tospecific circumstances, as discussed above with respect to the inventionembodiment depicted in FIG. 2A.

The invention is now further described by the following examples, whichare intended to be illustrative of the invention, but are not intendedto limit the scope or underlying principles in any way.

EXAMPLES Example 1 Bases of Calculations for Other Examples

(a) Membrane permeation experiments: The following calculations wereperformed using a composite membrane having a polyether-based selectivelayer with the properties shown in Table 1.

TABLE 1 Gas Permeance (gpu)* CO₂/Gas Selectivity Methane 90 11 Nitrogen30 33 Oxygen 60 17 Water 5,000**  — Carbon dioxide 1,000   — *Gaspermeation unit; 1 gpu = 1 × 10⁻⁶ cm³(STP)/cm² · s · cmHg **Estimated,not measured

(b) Calculation methodology: All calculations were performed using amodeling program, ChemCad 5.6 (ChemStations, Inc., Houston, Tex.),containing code for the membrane operation developed by MTR'sengineering group. For the calculations, all compressors and vacuumpumps were assumed to be 75% efficient. In each case, the modelingcalculation was performed to achieve the following results:

-   -   a concentration of at least about 15 volume % oxygen in the        oxygen-containing gas feed to the combustor;    -   a concentration of at least about 2 volume % oxygen in the        combustor exhaust stream (as a measure of complete combustion of        methane);    -   an oxygen-containing gas flow volume to the gas turbine which        provides at least twice the stoichiometric volume of oxygen        needed for complete fuel combustion (as a measure of dilution of        the combustion gas for adequate temperature control in the        turbine);    -   carbon dioxide recovery of at least about 80% in the carbon        dioxide-rich product stream.

Each calculation was performed reiteratively, varying the membrane area,sweep area flow to the membrane, and split ratios between the portionsof exhaust gas recycled, withdrawn, and passed to the membraneseparation step until the above desired set of results was achieved.

(c) “No membrane/no recycle” example: A computer calculation wasperformed to determine the chemical composition of untreated exhaust gasfrom a natural gas combustion process, such as might occur in a 500 MWcombined cycle power plant using about twice the stoichiometric ratio ofoxygen to fuel. FIG. 3 is a schematic drawing of a flow scheme for acombustion process that does not include either a recycle step or asweep-based membrane separation step.

Referring to FIG. 3, natural gas stream 301 and air stream 302 areintroduced as feed stream 303 into combustion step or zone 304. (Thecombustion step and the oxygen with which the fuel is combined are asdescribed in the Detailed Description, above.) To allow for cooling ofthe turbine, air is assumed to be provided at two times thestoichiometric amount required for combustion.

Combustion exhaust stream 305 is withdrawn, then routed through gasturbine 306 and a condenser (not shown) to knock water out of thestream. The chemical composition of the resulting untreated gas stream307 was then calculated. The results of this calculation are shown inTable 2.

TABLE 2 Stream Feed Gas to Combustion Turbine Methane Air StreamCombustor Exhaust Gas Exhaust Gas (301) (302) (303) (305) (307)Parameter Total Flow (kg/h) 86,000 3,290,000 3,376,000 3,376,0003,240,000 Temperature (° C.) 30 30 30 1,000 30 Pressure (bar) 30 30 301.0 1.1 Component (vol %) Methane 100 0 4.5 0 0 Oxygen 0 21.0 20.1 11.111.8 Nitrogen 0 79.0 75.5 75.5 80.5 Carbon Dioxide 0 0 0 4.5 4.8 Water 00 0 9.0 2.8

After the water vapor in the stream is condensed, the carbon dioxideconcentration in the turbine exhaust stream 307 is 4.8 volume %, whichis too low to enable economical carbon dioxide capture by traditionalmeans, such as absorption or low-temperature condensation. Emitting sucha flue gas stream from a power plant would release over 6,000 tons ofcarbon dioxide per day to the environment.

Example 2 Combustion Process with Partial Flue Gas Recycle and NoSweep-Based Membrane Separation (Not in Accordance with the Invention)

A computer calculation was performed to determine the chemicalcomposition of exhaust gas from a natural gas combustion process, withpartial flue gas recycle and no membrane sweep. The process differedfrom the base-case calculation of Example 1 in that the intake of airwas reduced to about half that of Example 1 (in other words, the minimumamount to provide for complete combustion), and the remainder of the gasrequired for temperature and flow control in the combustor was assumedto be provided by recirculating a portion of the combustion exhaust gasto the combustor inlet, as is commonly done. FIG. 4 is a schematicdrawing of a flow scheme for such a combustion process.

Referring to FIG. 4, natural gas stream 401 and compressedoxygen-containing gas stream 409 are introduced as feed stream 403 intocombustion step or zone 404. Stream 409 is made up of recycled exhauststream 408 and additional air or oxygen supply stream 402.

Combustion exhaust stream 405 is withdrawn, then routed through gasturbine 406 and a condenser (not shown) to knock water out of thestream. The dehydrated turbine exhaust stream 407 is then routed througha splitter, where it is divided into a first portion 408 and a secondportion 410. The first portion 408 of the dehydrated exhaust stream iscombined with additional air stream 402 and routed back to the combustor404 as oxygen-containing gas stream 409. The second portion 410 iswithdrawn.

The chemical composition of the portion 408 of the untreated gas streamwhich is routed back to the combustor 404 was then calculated. Theresults of this calculation are shown in Table 3.

To facilitate operation of the calculation software, for Examples 2through 9, the base case air flow provided to the combustor via themembrane permeate side was assumed to be about 975 m³/h (1,250 kg/h),compared with the typical air flow to a 500 MW power plant of about 1.8million m³/h used for the calculation of Example 1. In other words, thescale of the calculation for the following Examples was about 1/1,200 ofthe scale for a typical natural gas-fired power plant. This reducesmembrane area proportionately, but does not affect the relative flowrates or compositions of the streams involved.

TABLE 3 Feed Gas Combus- Turbine Air to Com- tion Exhaust RecycleParameter/ Methane Stream bustor Exhaust Gas Gas Stream (401) (402)(403) Gas (405) (407) (408) Total Flow 71.6 1,370 1,440 1,440 1,3001,370 (kg/h) Temper- 30 30 30 1,000 30 30 ature (° C.) Pressure 30 30 301.0 1.1 1.1 (bar) Component (vol %) Methane 100 0 8.6 0 0 0 Oxygen 021.0 19.2 2.0 2.4 2.4 Nitrogen 0 79.0 72.2 72.2 84.7 84.7 Carbon 0 0 08.6 10.0 10.0 Dioxide Water 0 0 0 17.2 2.8 2.8

By recycling a portion of the turbine exhaust gas back to the combustor,the oxygen content o the feed gas 403 is reduced to 19.2 volume %, butstill enough to produce 2.0 volume % oxygen in the combustion exhaustgas 405. More importantly, the carbon dioxide in the exhaust gas stream407 is increased to 10 volume %.

Example 3 Combustion Process with Membrane Sweep and No Flue Gas Recycle(Not in Accordance with the Invention)

A computer calculation was performed to determine the chemicalcomposition of exhaust gas from a natural gas combustion process, withmembrane sweep, but no flue gas recycle. FIG. 5 is a schematic drawingof a flow scheme for such a combustion process.

Referring to FIG. 5, natural gas stream 501 and compressed combinedsweep/permeate stream 512 are introduced as feed stream 503 intocombustion step or zone 504. The mass flow rate of the natural gasstream 501 was 71.6 kg/h.

Combustion exhaust stream 505 is withdrawn, then routed through gasturbine 506 and a condenser (not shown) to knock water out of thestream. The dehydrated turbine exhaust stream 507 is then routed througha splitter, where it is divided into a first portion 508 and a secondportion 509. In this example, the first portion 508 and the secondportion 509 were in a ratio of 1:5.6 (flow to carbon dioxidewithdrawal:flow to membrane separation). The first portion 508 of thedehydrated exhaust stream is withdrawn; the second portion 509 is sentfor treatment in a sweep-based membrane separation step 510 usingmembranes 511 having the properties listed in Table 1. A sweep stream502 of air is flowed across the permeate side of the membrane. The flowrate of sweep stream 502 was 2,070 kg/h.

The resulting permeate stream 512 is then routed back to the combustor504. The exhaust stream 513 is released to the atmosphere. The chemicalcompositions of the various streams were calculated. The results of thiscalculation are shown in Table 4.

TABLE 4 Gas to Mem- Mem- Ex- Com- Flue CO2 brane brane haust Parameter/bustor Gas Product Feed Permeate Gas Stream (503) (505) (508) (509)(512) (513) Total Flow 3,070 3,070 440 2,470 3,000 1,550 (kg/h) Temper-30 1,000 30 30 30 30 ature (° C.) Pressure 30 30 1.1 1.1 1.1 1.0 (bar)Component (vol %) Methane 4.5 0 0 0 0 0 Oxygen 14.4 5.4 5.9 5.9 15.1 9.9Nitrogen 60.0 60.0 65.6 65.6 62.8 88.4 Carbon 19.0 23.5 25.6 25.6 19.91.7 Dioxide Water 2.2 11.2 2.8 2.8 2.3 0

The oxygen content of the untreated flue gas 505 was 5.4 volume %. Thecarbon dioxide content of withdrawn product stream 508 was 25.6 volume%. The oxygen content of the membrane permeate stream 512 that is routedback to the combustor was 15.1 volume %. The carbon dioxide content ofthe exhaust stream 513 that is to be released to the environment wasreduced to 1.7 volume %. Total carbon dioxide recovery from the processwas 79.3 volume %.

To achieve these results required a membrane area of 1,800 m², a sweepstream flow rate of 2,070 kg/h, and a split ratio between gas withdrawnas stream 508 and gas sent as stream 509 for treatment in the membraneof about 1:5.

Example 4 Combustion Process with Membrane Sweep and Post-CombustionFlue Gas Recycle, with 1:5 Split Ratio (in Accordance with theInvention)

The calculations for this Example were performed using the flow schemeshown in FIG. 1B and described in the Detailed Description, above. Thisflow scheme includes a sweep-based membrane separation step 162, whichwas assumed to be carried out using membranes 163 having the permeationproperties listed in Table 1.

The mass flow rate of the natural gas stream 161 was 71.6 kg/h. Theresults of this calculation are shown in Table 5.

TABLE 5 Gas to Re- Mem- Mem- Ex- Com- Flue cycle CO2 brane brane haustParameter/ bustor Gas Gas Product Feed Permeate Gas Stream (153) (155)(158) (160) (161) (164) (165) Total Flow 2,600 2,600 490 430 2,000 2,5001,250 (kg/h) Temper- 30 1,000 30 30 30 30 30 ature (° C.) Pressure 30 301.1 1.1 1.1 1.1 1.0 (bar) Component (vol %) Methane 5.3 0 0 0 0 0 0Oxygen 14.2 3.6 4.0 4.0 4.0 15.0 7.7 Nitrogen 59.9 59.9 66.7 66.7 66.763.2 90.2 Carbon 18.5 23.8 26.4 26.4 26.4 19.5 2.0 Dioxide Water 2.112.7 2.8 2.8 2.8 2.2 0

The oxygen content of the untreated flue gas 155 was 3.6 volume %. Thecarbon dioxide content of the recycle gas stream 158 and the withdrawnproduct stream 160 was 26.4 volume %, and the oxygen content of the gaswas 4.0 volume %. The oxygen content of the membrane permeate stream 164that is routed back to the combustor was 15.0 volume %. This was enoughto combust the incoming fuel gas without a problem. However, if mixedwith stream 158 before the combustor, the oxygen content would not besufficient to produce a stable flame in the combustor. For this reason,the recycle (diluent) gas stream 158 is mixed with the stream 155 aftercombustion. This mixing process could occur within the turbine or beforethe turbine.

As described above, mixing the recycle gas stream with the main gasstream after the combustion step maintains a higher oxygen concentrationin the combustor, but the process requires two compressors. Onecompressor is used to compress stream 159, and another compressor isused to compress bypass stream B1. If the gas is mixed before thecombustion, then the oxygen content of the gas in the combination willbe lower, which may produce flame stability problems, but only onecompressor is required for mixed stream 159.

The carbon dioxide content of the exhaust stream 165 that is to bereleased to the environment was 2.0 volume %. Total carbon dioxiderecovery from the process was 78.7 volume %.

To achieve these results required a membrane area of 1,320 m², a sweepstream flow rate of 1,760 kg/h, and split ratios 1:5 (flow torecycle:flow to carbon dioxide withdrawal and sweep-based membraneseparation step) and 1:4.9 (flow to withdrawal:flow to sweep).

Comparing Examples 3 and 4, it can be seen that the process of theinvention, incorporating both sweep-based membrane separation andrecycle of a portion of untreated flue gas, offers benefits andadvantages. The invention can achieve comparable results, in terms ofconcentration of carbon dioxide in the product stream and total carbondioxide recovery, using considerably less membrane area and a smallerflow of sweep gas.

Example 5 Combustion Process with Membrane Sweep and Post-CombustionFlue Gas Recycle, with 1:3 Split Ratio (in Accordance with theInvention)

The calculations for this Example were performed using the flow schemeshown in FIG. 1B and described in the Detailed Description, above. Thisflow scheme includes a sweep-based membrane separation step 162, whichwas assumed to be carried out using membranes 163 having the permeationproperties listed in Table 1.

The mass flow rate of the natural gas stream 151 was 71.6 kg/h. Theresults of this calculation are shown in Table 6.

TABLE 6 Gas to Re- Mem- Mem- Ex- Com- Flue cycle CO2 brane brane haustParameter/ bustor Gas Gas Product Feed Permeate Gas Stream (153) (155)(158) (160) (161) (164) (165) Total Flow 2,350 2,350 730 420 1,800 2,2801,100 (kg/h) Temper- 30 1,000 30 30 30 30 30 ature (° C.) Pressure 30 301.1 1.1 1.1 1.1 1.0 (bar) Component (vol %) Methane 5.8 0 0 0 0 0 0Oxygen 14.1 2.5 2.8 2.8 2.8 15.0 6.3 Nitrogen 59.8 59.8 67.3 67.3 67.363.4 91.4 Carbon 18.3 24.1 27.1 27.1 27.1 19.4 2.3 Dioxide Water 2.013.6 2.8 2.8 2.8 2.2 0

The oxygen content of the untreated flue gas 155 was 2.5 volume %. Thecarbon dioxide content of the recycle gas stream 158 and the withdrawnproduct stream 160 was 27.1 volume %. The oxygen content of the membranepermeate stream 164 that is routed back to the combustor was 15.0 volume%. The carbon dioxide content of the exhaust stream 165 that is to bereleased to the environment was 2.3 volume %. Total carbon dioxiderecovery from the process was 79.0 volume %.

To achieve these results required a membrane area of 1,110 m², a sweepstream flow rate of 1,610 kg/h, and split ratios of 1:3 (flow torecycle:flow to carbon dioxide withdrawal and sweep-based membraneseparation step) and 1:4.2 (flow to withdrawal:flow to sweep-basedmembrane separation).

Compared with Example 4, the membrane area and the air flow to thecombustor were both decreased, and the amount of gas recycled to thecombustor was increased; however, similar overall results were achieved.

Example 6 Combustion Process with Two Membrane Steps and Post-CombustionFlue Gas Recycle, with 1:3 Split Ratio (in Accordance with theInvention)

The calculations for this Example were performed using the flow schemeshown in FIG. 2B and described in the Detailed Description, above. Thisflow scheme includes a membrane-based carbon dioxide capture step 260,followed by a sweep-based membrane separation step 264. The membranesteps 260 and 264 were assumed to be carried out using membranes 261 and265 having the permeation properties listed in Table 1.

The mass flow rate of the natural gas stream 251 was 71.6 kg/h. Theresults of this calculation are shown in Table 7.

TABLE 7 Gas to Re- Mem- Mem- Ex- Com- Flue cycle CO2 brane brane haustParameter/ bustor Gas Gas Product Feed Permeate Gas Stream (253) (255)(258) (262) (263) (266) (267) Total Flow 2,300 2,300 720 215 1,930 2,2301,400 (kg/h) Temper- 30 1,000 30 30 30 30 30 ature (° C.) Pressure 30 301.1 0.375 1.1 1.1 1.0 (bar) Component (vol %) Methane 5.8 0 0 0 0 0 0Oxygen 14.8 3.2 3.6 2.4 3.7 15.7 6.7 Nitrogen 63.8 63.8 71.7 26.6 75.867.7 91.6 Carbon 13.8 19.6 21.9 61.6 18.3 14.6 1.7 Dioxide Water 1.813.4 2.8 9.5 2.2 1.9 0

The oxygen content of the untreated flue gas 255 was 3.2 volume %. Thecarbon dioxide content of the recycle gas stream 258 was 21.9 volume %.The carbon dioxide content of the product stream 262 after the firstmembrane step 260 was 61.6 volume %. The oxygen content of the membranepermeate stream 266 that is routed back to the combustor was 15.7 volume%. The carbon dioxide content of the exhaust stream 267 that is to bereleased to the environment was 1.7 volume %. Total carbon dioxiderecovery from the process was 80.5 volume %.

To achieve these results required a total membrane area of 1,775 m² (425m² for the first membrane step and 1,350 m² for the second membranestep), a sweep stream flow rate of 1,700 kg/h, and a split ratio of 1:3(flow to recycle:flow to membrane steps).

This process uses only 1.1% of the energy generated by the powergeneration process (5.6 kW out of a total of 491 kW). This example showsthat the carbon dioxide capture membrane can achieve carbon dioxidepurity up to nearly 62 volume % using very little extra energy. At thesame time, the sweep flow rate and the total membrane area are modest.

Example 7 Combustion Process with Two Membrane Steps and Pre-CombustionFlue Gas Recycle, with 1:3 Split Ratio (in Accordance with theInvention)

The calculations for this Example were performed using the flow schemeshown in FIG. 2B and described in the Detailed Description, above. Thisflow scheme includes a membrane-based carbon dioxide capture step 260,followed by a sweep-based membrane separation step 264. The membranesteps 260 and 264 were assumed to be carried out using membranes 261 and265 having the permeation properties listed in Table 1.

Unlike in the previous examples, where the recycle gas 258 is sent backto the power generation process between the combustion step 254 and theturbine step 256, in this example, the recycle gas, D1, is sent back tothe power generation process prior to the combustion step 254. In thisexample, the recycle gas 258 was assumed to have been run through onlyone compressor (not shown) before being returned to the power generationprocess.

The mass flow rate of the natural gas stream 251 was 71.6 kg/h. Theresults of this calculation are shown in Table 8.

TABLE 8 Gas to Re- Mem- Mem- Ex- Com- Flue cycle CO2 brane brane haustParameter/ bustor Gas Gas Product Feed Permeate Gas Stream (253) (255)(269) (262) (263) (266) (267) Total Flow 3,010 3,010 720 215 1,930 2,2301,400 (kg/h) Temper- 30 1,000 30 30 30 30 30 ature (° C.) Pressure 30 301.1 0.375 1.1 1.1 1.0 (bar) Component (vol %) Methane 4.5 0 0 0 0 0 0Oxygen 12.2 3.3 3.6 2.4 3.9 15.7 6.7 Nitrogen 65.6 65.6 71.7 26.6 75.967.8 91.6 Carbon 15.6 20.1 21.9 61.5 18.2 14.6 1.7 Dioxide Water 2.011.0 2.8 9.5 2.2 1.9 0

The oxygen content of the untreated flue gas 255 was 3.3 volume %. Thecarbon dioxide content of the recycle gas stream 269 was 21.9 volume %.The carbon dioxide content of the product stream 262 after the firstmembrane step 260 was 61.5 volume %. The oxygen content of the membranepermeate stream 266 that is routed to the combustor was 14.6 volume %.The carbon dioxide content of the exhaust stream 267 that is to bereleased to the environment was 1.7 volume %. Total carbon dioxiderecovery from the process was 80.5 volume %.

To achieve these results required a total membrane area of 1,775 m²(425m² for the first membrane step and 1,350 m² for the second membranestep), a sweep stream flow rate of 1,700 kg/h, and a split ratio of 1:3(flow to recycle:flow to membrane steps).

The oxygen content of the feed gas stream 253 to the combustor was toolow at 12.2 volume %, for the reasons described earlier. This may leadto flame stability and incomplete combustion of the methane fuel.

Example 8 Combustion Process with Two Membrane Steps and Pre-CombustionFlue Gas Recycle, with 1:10 Split Ratio (in Accordance with theInvention)

The calculations for this Example were performed using the flow schemeshown in FIG. 2B and described in the Detailed Description, above. Thisflow scheme includes a membrane-based carbon dioxide capture step 260,followed by a sweep-based membrane separation step 264. The membranesteps 260 and 264 were assumed to be carried out using membranes 261 and265 having the permeation properties listed in Table 1. As in Example 7,in this example, the recycle gas, D1, is sent back to the powergeneration process prior to the combustion step 254.

The mass flow rate of the natural gas stream 251 was 71.6 kg/h. Theresults of this calculation are shown in Table 9.

TABLE 9 Gas to Re- Mem- Mem- Ex- Com- Flue cycle CO2 brane brane haustParameter/ bustor Gas Gas Product Feed Permeate Gas Stream (253) (255)(269) (262) (263) (266) (267) Total Flow 2,940 2,940 255 250 2,290 2,6151,760 (kg/h) Temper- 30 1,000 30 30 30 30 30 ature (° C.) Pressure 30 301.1 0.375 1.1 1.1 1.0 (bar) Component (vol %) Methane 4.5 0 0 0 0 0 0Oxygen 15.1 6.1 6.7 5.4 6.8 16.7 9.6 Nitrogen 66.7 66.7 72.8 33.2 76.569.6 89.1 Carbon 11.7 16.2 17.6 51.8 14.5 11.7 1.4 Dioxide Water 1.910.9 2.8 9.6 2.2 1.9 0

The oxygen content of the untreated flue gas 255 was 6.1 volume %. Thecarbon dioxide content of the recycle gas stream 269 was 17.6 volume %.The carbon dioxide content of the product stream 262 after the firstmembrane step 260 was 51.8 volume %. The oxygen content of the membranepermeate stream 266 that is routed back to the combustor was 16.7 volume%. The oxygen content of the feed gas stream 253 to the combustor is nowan acceptable 15.1 volume %. The carbon dioxide content of the exhauststream 267 that is to be released to the environment was 1.4 volume %.Total carbon dioxide recovery from the process was 79.2 volume %.

To achieve these results required a total membrane area of 2,290 m² (640m² for the first membrane step and 1,650 m² for the second membranestep), a sweep stream flow rate of 2,085 kg/h, and a split ratio of 1:10(flow to recycle:flow to membrane steps).

Compared with Example 7, by increasing the membrane area and air flow,and decreasing the proportion of the turbine exhaust gas that isrecycled back to the combustor, we were able to increase the amount ofoxygen in the feed to the combustor back to an acceptable level of 15.1volume %. This process uses only 1.3% of the energy generated by thepower generation process (6.7 kW out of a total of 491 kW).

1. A process for controlling carbon dioxide exhaust from combustion of agaseous fuel, comprising: (a) performing a power generation process,comprising (i) performing a combustion step by combusting a mixturecomprising a gaseous fuel and an oxygen-containing gas, therebygenerating a combustor exhaust stream comprising carbon dioxide andnitrogen, and (ii) routing the combustor exhaust stream as at least aportion of a working gas stream to a gas turbine, thereby generatingelectrical power and creating a turbine exhaust stream; (b) routing afirst portion of the turbine exhaust stream back to the power generationprocess as a recycle gas stream; (c) withdrawing a second portion of theturbine exhaust stream as a partially concentrated carbon dioxideproduct stream; (d) routing a third portion of the turbine exhauststream to a sweep-based membrane separation step, wherein thesweep-based membrane separation step comprises (i) providing a membranehaving a feed side and a permeate side, and being selectively permeableto carbon dioxide over nitrogen and to carbon dioxide over oxygen, (ii)passing a feed gas comprising the third portion of the turbine exhauststream across the feed side, (iii) passing air, oxygen-enriched air, oroxygen as a sweep stream across the permeate side, (iv) withdrawing fromthe feed side a carbon dioxide-depleted stream, (v) withdrawing from thepermeate side a permeate stream comprising oxygen and carbon dioxide;and (e) passing the permeate stream back to the power generationprocess.
 2. The process of claim 1, wherein at least a portion of therecycle gas stream is routed back to the power generation process afterthe combustion step, as part of the working gas stream to the gasturbine.
 3. The process of claim 1, wherein at least a portion of therecycle gas stream is routed back to the power generation process priorto the combustion step, as part of the oxygen-containing gas provided tothe combustion step.
 4. The process of claim 1, wherein at least aportion of the permeate stream is routed back to the power generationprocess after the combustion step, as part of the working gas stream tothe gas turbine.
 5. The process of claim 1, wherein at least a portionof the permeate stream is routed back to the power generation processprior to the combustion step, as part of the oxygen-containing gasprovided to the combustion step.
 6. The process of claim 1, wherein theoxygen-containing gas provided to the combustion step comprises at least15 volume % oxygen.
 7. The process of claim 1, wherein the combustorexhaust stream comprises at least 2 volume % oxygen.
 8. The process ofclaim 1, wherein the process recovers at least 80 volume % of the carbondioxide generated by the combustion step into the partially concentratedcarbon dioxide product stream.
 9. The process of claim 1, wherein thepartially concentrated carbon dioxide product stream contains at least20 volume % carbon dioxide.
 10. The process of claim 1, wherein themembrane exhibits a selectivity for carbon dioxide over oxygen of atleast
 10. 11. A process for controlling carbon dioxide exhaust fromcombustion of a gaseous fuel, comprising: (a) performing a combinedcycle power generation process, comprising (i) performing a combustionstep by combusting a mixture comprising a gaseous fuel and anoxygen-containing gas, thereby generating a combustor exhaust streamcomprising carbon dioxide and nitrogen, (ii) routing the combustorexhaust stream as at least a portion of a working gas stream to a gasturbine, thereby generating electrical power and creating a turbineexhaust stream, (iii) routing at least a portion of the turbine exhauststream to a boiler, thereby generating steam and creating a boilerexhaust stream, and (iv) routing the steam to a steam turbine, therebygenerating additional electrical power; (b) routing a first portion ofthe boiler exhaust stream back to the power generation process as arecycle gas stream; (c) withdrawing a second portion of the boilerexhaust stream as a partially concentrated carbon dioxide productstream; (d) routing a third portion of the boiler exhaust stream to asweep-based membrane separation step, wherein the sweep-based membraneseparation step comprises (i) providing a membrane having a feed sideand a permeate side, and being selectively permeable to carbon dioxideover nitrogen and to carbon dioxide over oxygen, (ii) passing a feed gascomprising the third portion of the boiler exhaust stream across thefeed side, (iii) passing air, oxygen-enriched air, or oxygen as a sweepstream across the permeate side, (iv) withdrawing from the feed side acarbon dioxide-depleted stream, (v) withdrawing from the permeate side apermeate stream comprising oxygen and carbon dioxide; and (e) passingthe permeate stream back to the power generation process.
 12. Theprocess of claim 11, wherein at least a portion of the recycle gasstream is routed back to the power generation process after thecombustion step, as part of the working gas stream to the gas turbine.13. The process of claim 11, wherein at least a portion of the recyclegas stream is routed back to the power generation process prior to thecombustion step, as part of the oxygen-containing gas provided to thecombustion step.
 14. The process of claim 11, wherein at least a portionof the permeate stream is routed back to the power generation processafter the combustion step, as part of the working gas stream to the gasturbine.
 15. The process of claim 11, wherein at least a portion of thepermeate stream is routed back to the power generation process prior tothe combustion step, as part of the oxygen-containing gas provided tothe combustion step.
 16. The process of claim 11, wherein theoxygen-containing gas provided to the combustion step comprises at least15 volume % oxygen.
 17. The process of claim 11, wherein the combustorexhaust stream comprises at least 2 volume % oxygen.
 18. The process ofclaim 11, wherein the process recovers at least 80 volume % of thecarbon dioxide generated by the combustion step into the partiallyconcentrated carbon dioxide product stream.
 19. The process of claim 11,wherein the partially concentrated carbon dioxide product streamcontains at least 20 volume % carbon dioxide.
 20. The process of claim11, wherein the membrane exhibits a selectivity for carbon dioxide overoxygen of at least 10.